Gas turbine system with diffusion flame combustion and fuel mixing for reducing undesirable emissions

Abstract

A gas turbine system (1000, 2000, 3000) having a compressor section (10) configured to compress an oxidant stream and provide a compressed oxidant stream in a combustor section (20). The combustor section (20) is configured to receive an oxidant and a fuel gas mixture including at least a fuel gas and an inert gas separately, perform a diffusion flame combustion of the fuel and the oxidant in a combustion chamber, and provide a flue gas stream to a turbine section (30), which is configured to expand the flue gas stream and discharge the expanded flue gas stream at a turbine outlet. The gas turbine system also has a mixing unit (50) configured to mix at least the fuel gas and the inert gas and provide a fuel gas mixture in the combustor section (20) in a mixing ratio that depends on the flue gas content, for example on the measured or predicted NOx and / or CO and / or CO2 content of the flue gas. The mixing unit (50) is configured to mix at least the fuel gas and the inert gas under the control of a control unit (40) configured to control the operation of the gas turbine system.

Description

Technical Field

[0001] The subject matter disclosed herein relates to a gas turbine system with diffusion flame combustion and fuel mixing for partially or completely reducing undesirable emissions, particularly NOx emissions, and in some cases CO and / or CO2 emissions, by adjusting fuel mixing. The adjustment of fuel mixing is advantageously performed based on the NOx and / or CO and / or CO2 content in the flue gas of the gas turbine system.

Background Art

[0002] Conventional gas turbine engines operate by compressing an oxidizer, typically air, to high pressure, combusting fuel with the oxidizer to generate a high-pressure, high-temperature flue gas stream, and then expanding the high-pressure, high-temperature flue gas stream through an expander to produce work and, in some cases, generate electrical energy. Typically, gas turbine engines use natural gas, which consists mainly of methane and contains only a very small amount of slightly heavier hydrocarbons such as ethane, propane, and butane, or liquefied petroleum gas, which is propane and / or butane and contains trace amounts of heavier hydrocarbons, as fuel.

[0003] Gas turbine combustion systems are of two types: diffusion flames or premixed flames. In a diffusion combustion system, fuel and an oxidizer (e.g., air) are injected separately into the reaction zone of the combustor to perform combustion that is completely or nearly stoichiometric. However, in a diffusion combustion system, due to the fact that the combustion is completely or nearly stoichiometric, it is difficult (if not impossible) to control NOx emissions, particularly the formation of "thermal NOx," which is formed from the oxidation of free nitrogen in the oxidizer (e.g., air) or fuel. Thermal NOx strongly depends on the stoichiometric adiabatic flame temperature of the fuel, which is the temperature reached by combusting a stoichiometric mixture of fuel and an oxidizer (e.g., air) in an adiabatic container, and more weakly on the concentrations of oxygen and nitrogen.

[0004] In the past few decades, emission regulations have become more stringent to limit environmental damage. Attempts have been made to limit NOx emissions from diffusion flame combustion systems by directly adding water or steam to the reaction zone of the combustor to lower the flame temperature. Other attempts have been made to remove NOx (and in some cases CO and / or CO2 as well) directly from the flue gas stream. For example, NOx emissions can be reduced by adding a selective catalytic reduction system downstream of the expander in a gas turbine system.

[0005] However, the further strengthening of recent emission requirements has led to the introduction and widespread use of premixed combustion systems such as dry low NOx (DLN) or dry low emissions (DLE) combustors. In premixed combustors, the fuel and the oxidizer (e.g., air) are mixed upstream of the reaction zone of the combustor and are thus typically optimized for low NOx emission operation. For example, in a DLN gas turbine combustor, systems and methods for mixing a secondary gas, such as an alternative gas fuel like hydrogen, ethane, butane, propane, LNG, or an inert gas such as nitrogen and carbon dioxide, with a primary gas fuel, particularly natural gas, are known from European Patent No. 2204561 (A2). In these types of combustors, the amount of hydrogen to be mixed is limited due to the risk of flame instability, and thus a significant amount of natural gas is always present, resulting in a relatively high amount of CO and / or CO2 emissions. Therefore, premixed combustion does not enable reaching complete decarbonization of the system.

Summary of the Invention

Problems to be Solved by the Invention

[0006] However, even if conventional diffusion combustion systems may have NOx emission problems considering at least the constantly increasing low emission requirements, they still offer higher fuel flexibility, higher flame stability, and lower (or even zero) CO and CO2 emissions compared to premixed combustors.

[0007] It would be desirable to have a gas turbine system with a diffusion flame combustion that partially or fully reduces undesirable emissions, particularly NOx emissions and possibly CO and / or CO2 emissions.

[0008] In particular, it would be desirable to provide a solution that offers higher fuel flexibility, higher flame stability compared to a premixed combustor, and a solution that can provide lower amounts of CO and / or CO2 emissions, for example, a solution that can combust a fuel having up to 100% by volume of hydrogen (and for example up to 0% by volume of natural gas or another secondary fuel). The hydrogen can be, for example, 50%, 60%, 70%, 80% or 90% and can vary over time for different reasons.

[0009] In particular, it would be desirable to provide a solution that can be easily applied even to gas turbine systems that are already installed and operating, so that these systems can comply with more stringent emission requirements.

[0010] According to one aspect, the subject matter disclosed herein relates to a gas turbine system having a compressor section configured to compress an oxidant stream and provide a compressed oxidant stream to a combustor section, where in the combustor section, a gas mixture of fuel gas and inert gas is further supplied separately from the oxidant. The combustor section is configured to perform diffusion flame combustion of fuel and oxidant in a combustion chamber and provide a flue gas stream to a turbine section configured to expand the flue gas stream and discharge an expanded flue gas stream at a turbine outlet. The gas turbine system also has a mixing unit configured to mix at least fuel gas and inert gas and provide a gas mixture in the combustor section at a mixing ratio according to the content of the flue gas, for example, according to the NOx and / or CO and / or CO2 content of the flue gas. The mixing unit is configured to mix the fuel gas and the inert gas under the control of a control unit configured to control the operation of the gas turbine system.

[0011] Considering the possibility of retrofit, such an innovative gas turbine system is particularly suitable for combusting air with hydrogen or a gas mixture containing hydrogen. Preferably, the inert gas is nitrogen or mainly contains nitrogen because it is readily available and low-cost.

Brief Description of the Drawings

[0012] Regarding many of the disclosed embodiments of the present invention and their attendant advantages, when considered in connection with the accompanying drawings, a complete understanding will be readily obtained by referring to the following detailed description of how to implement the invention, as they will be better understood thereby.

Figure 1

Figure 2

Figure 3

Detailed Description of the Invention

[0013] According to one aspect, the subject matter disclosed herein relates to a gas turbine system having diffusion flame combustion that enables the reduction of undesirable emissions, particularly NOx emissions, and optionally CO and / or CO2 emissions, by mixing a fuel gas, such as hydrogen, with an inert gas, such as nitrogen, and optionally an additional fuel gas, such as natural gas. The amounts of fuel gas, inert gas, and additional fuel gas in the gas mixture are controlled by a control unit that adjusts the opening and closing of inlet valves supplying the gases to a mixing unit. The mixing unit produces a gas mixture that is combusted with an oxidant, such as air, in a diffusion flame combustor of the gas turbine to produce flue gas, which is expanded in an expander of the gas turbine and typically drives equipment, such as a compressor or a generator, mechanically coupled to the gas turbine. The flue gas may then be discharged into the atmosphere. To keep undesirable emissions (e.g., harmful emissions) low, the system is provided with a continuous emissions monitoring system, typically consisting of the placement of sensors, or a predicted emissions monitoring system, typically consisting of hardware and / or software analyzers, each of which measures or predicts the amount of NOx and / or CO and / or CO2 in the expanded flue gas and provides the amount to the control unit, which controls the content of the gas mixture based on the measured or predicted amount.

[0014] Next, embodiments of the present disclosure will be described in detail, and examples thereof are illustrated in the drawings. The examples and drawings are provided as an explanation of the present disclosure and should not be construed as limiting the present disclosure. In fact, it will be apparent to those skilled in the art that various modifications and variations can be made to the present disclosure without departing from the scope or spirit of the present disclosure. In the following description, like reference numerals are used in the illustration of the embodiments of the figures to indicate elements that perform the same or similar functions. Further, for the sake of clarity of illustration, some reference numerals may not be repeated in all the figures.

[0015] Figure 1 shows a schematic view of an embodiment of a gas turbine system involving diffusion flame combustion and fuel mixing, and the entire gas turbine system is designated by reference numeral 1000. The gas turbine system 1000 includes a compressor section 10, a combustor section 20, and a turbine section 30. Typically, the compressor section 10 and the turbine section 30 are mechanically coupled by a shaft 34. Advantageously, the shaft 34 is further mechanically coupled to a driven device 35, such as a compressor or a generator.

[0016] The compressor section 10 has a compressor inlet 11 and a compressor outlet 12, and is configured to receive an uncompressed oxidant stream, preferably air, more preferably ambient air at ambient pressure, at the compressor inlet, and compress the oxidant through, for example, one or more compressor stages to provide a compressed oxidant stream at the compressor outlet 12. As will become apparent hereinafter, the compressed oxidant stream is then supplied to the combustor section 20 of the gas turbine system 1000.

[0017] The combustor section 20 has a combustor inlet 21 and a combustor outlet 22, and is configured to receive a compressed oxidant stream from the compressor section 10, particularly from the compressor outlet 12. In other words, the combustor inlet 21 is fluidly coupled to the compressor outlet 12. The combustor section 20 is configured to perform diffusion flame combustion of fuel and oxidant in a combustion chamber, and the combustion chamber is fluidly coupled to a combustor inlet 21 for receiving the compressed oxidant and a fuel supply conduit 23 for receiving fuel. As will be better explained below, the fuel received in the combustion chamber is a gas mixture of fuel gas and an inert gas. The combustion performed within the combustor section 20 generates a flue gas stream provided at the combustor outlet 22.

[0018] The combustor outlet 22 is fluidly coupled to the turbine section 30. The turbine section 30 has a turbine inlet 31 and a turbine outlet 32, and is configured to expand the flue gas stream through, for example, one or more expansion stages and discharge the expanded flue gas stream, which typically reaches the atmosphere, at the turbine outlet 32.

[0019] As already explained above, the combustor section 20 is configured to receive at least a gas mixture of fuel gas and inert gas, and the gas turbine system 1000 further includes a mixing unit 50 configured to mix fuel gas and inert gas and supply the gas mixture to the combustor section 20. The mixing unit 50 has at least a fuel gas inlet 51, an inert gas inlet 52, and a gas mixture outlet 54, and the gas mixture outlet 54 is fluidly coupled to the fuel supply conduit 23 of the combustor section 20 to provide the gas mixture to the combustor section 20. In particular, the mixing unit 50 is arranged upstream of the combustor section 20.

[0020] According to a preferred embodiment, the fuel gas may be, for example, hydrogen or a gas mixture containing mainly hydrogen, for example containing at least 90% hydrogen (e.g., depending on the purity of the hydrogen supplied to the mixing unit 50). According to a preferred embodiment, the inert gas may contain nitrogen and / or carbon dioxide and / or argon and / or helium and / or a mixture thereof. H2O is not excluded from being used as an "inert gas" (either alone or in combination with one or more other inert gases), preferably in the form of steam or spray water or atomized water, even if its "inertness" is low. Preferably, the inert gas contains nitrogen or mainly nitrogen, for example containing at least 90% nitrogen (e.g., depending on the purity of the nitrogen supplied to the mixing unit 50). For example, the inert gas may be nitrogen coming from an Air Separation Unit (ASU). By using a hydrogen or hydrogen-containing gas mixture as the fuel gas, the CO and CO2 emissions are extremely low (even if not zero). This does not apply when natural gas or ammonia or LPG or biofuel or electric fuel or syngas is used as a substitute for the fuel.

[0021] The composition of the fuel gas mixture can have a very large number of possibilities. According to a first possibility, the gas mixture supplied to the combustor section 20 at a certain time can, for example, substantially contain, for example, about 60% by volume of hydrogen and, for example, about 40% by volume of nitrogen. Advantageously, this composition of the gas mixture does not generate CO or CO2 in the flue gas because the main product of this combustion is H2O. Also, generally, as the inert component in the gas mixture increases, the expansion mass flow rate in the turbine section 30 increases (the inert gas can be heated in the combustor section 20 and expand in the turbine section 30), while the compression mass flow rate does not change (since the inert gas does not affect the combustion reaction, the amount of oxidant compressed by the compression section 10 does not change), so it should also be noted that it can have a positive effect on the power output of the gas turbine system 1000. According to certain operating conditions, when hydrogen is insufficient, the hydrogen content in the gas mixture can be, for example, less than 60% (for example, when hydrogen is obtained from renewable resources, especially intermittent renewable resources), and additional fuel gas can be added to the gas mixture, as will be better explained below. According to other specific operating conditions, for example, at the start of the turbine, additional fuel gas may be added to the gas mixture (or hydrogen may be completely replaced), as will be better explained below. Generally, it should be noted that the composition of the fuel gas mixture may not always be the same for different reasons (including that the composition is controlled by the control unit) and may vary from embodiment to embodiment.

[0022] As shown in FIGS. 1 to 3, the mixing units 50, 150, 250 can further include additional fuel gas inlets 53, 153, 253. For example, the additional fuel gas can be natural gas and / or ammonia and / or liquefied petroleum gas (LPG) and / or biofuel (i.e., fuel produced from biomass) and / or e-fuel (i.e., fuel produced with fossil-free electricity or electricity derived from renewable sources) and / or syngas (i.e., a gas mixture mainly consisting of hydrogen and carbon monoxide) and / or contain CO. The additional fuel gas may be mixed with the fuel gas and the inert gas by the mixing units 50, 150, 250, and the resulting gas mixture may be provided at the gas mixture outlets 54, 154, 254 of the mixing units 50, 150, 250. The use of the additional fuel gas can be advantageous, especially during the start-up of the gas turbine systems 1000, 2000, 3000. For example, CO may react with O2 according to the following reaction. 2CO + O2 → 2CO2

[0023] With non-limiting reference to FIGS. 1 to 3, the gas turbine systems 1000, 2000, 3000 further include control units 40, 140, 240 configured to control the operation of the gas turbine systems, in particular to control the opening and closing of the fuel gas regulating valves, the inert gas regulating valves, and the additional fuel gas regulating valves (when additional fuel gas is provided) of the mixing units 50, 150, 250. The mixing units 50, 150, 250 generate a gas mixture under the control of the control units 40, 140, 240. As will become apparent hereinafter, the content of the flue gas at the turbine outlets 32, 132, 232, for example, the content of NOx and / or the content of CO and / or the content of CO2, is measured and / or predicted and provided to the control units 40, 140, 240. Advantageously, the control unit 40 adjusts the opening and closing of the regulating valve according to the measured / predicted content of the flue gas. In other words, the gas mixture has a mixing ratio according to the measured / predicted content of the flue gas.

[0024] FIG. 1 shows an embodiment of a gas turbine system 1000 further comprising a continuous emissions monitoring system (= CEMS) 70 fluidly coupled to a turbine outlet 32 and configured to determine at least one parameter of an expanding flue gas stream at the turbine outlet 32. Typically, as already described, the continuous emissions monitoring system 70 consists of an arrangement of sensors capable of measuring one or more parameters to be controlled. Advantageously, the continuous emissions monitoring system 70 can measure the amount of NOx in the expanding flue gas stream, and / or the amount of CO in the expanding flue gas stream, and / or the amount of CO2 in the expanding flue gas stream. The continuous emissions monitoring system 70 can provide the parameter(s) to a control unit 40, which can, based on the measured parameter(s), preferably based at least on the amount of NOx in the expanding flue gas stream and / or the amount of CO in the expanding flue gas stream and / or the amount of CO2 in the expanding flue gas stream, provide it to a control unit 40 that controls the operation of the gas turbine system 1000. In particular, as already described, the control unit 40 can control the opening and closing of a regulating valve based on the parameter(s) detected by the continuous emissions monitoring system 70.

[0025] Advantageously, the gas turbine system 1000 can further comprise devices, particularly sensors, for measuring other parameters such as the following (these devices may also be integrated in whole or in part into the mixing unit and / or the compressor section and / or the combustor section and / or the turbine section). - Ambient pressure and temperature, and / or - Expanding flue gas temperature, and / or - Ambient relative humidity, and / or - Pressure drop between the compressor inlet 11 and the ambient pressure, and / or - Pressure drop between the turbine outlet 32 and the ambient pressure, and / or - Pressure and temperature of an oxidant (e.g., air) at the compressor outlet 12, and / or - Flame temperature, and / or - Flame stability and kinetics, and / or - Fuel composition and characteristics (pressure, temperature, Lower Heating Value (LHV), Modified Wobbe Index (MWI), combustion ratio, etc.).

[0026] Advantageously, one or more of these other parameters can be supplied to the control unit 40, which can take them into account to control the operation of the gas turbine system 1000 and, in particular, perform a trade-off between the amount of undesirable emissions (e.g., NOx and / or CO and / or CO2) and the gas turbine performance. Advantageously, the control unit 40 can also take into account the aging phenomenon of the gas turbine system and / or the mechanical degradation / wear of the high-temperature gas components (i.e., the gas turbine components exposed to the high-temperature flow), for example, based on predictions and gas turbine performance maps, to control the operation of the gas turbine system 1000. The control unit 40 can be further connected to the fuel gas analyzer 60 and fluidly coupled to the gas mixture outlet 54, thereby providing information about the gas mixture at the gas mixture outlet 54. For example, the fuel gas analyzer 60 can measure the composition and characteristics specified above. Advantageously, the control unit 40 controls the content of the gas mixture based further on the information provided by the fuel gas analyzer 60.

[0027] FIG. 2 shows another embodiment of a gas turbine system 2000 that is similar to the embodiment of FIG. 1, but differs in that at least the parameter(s) of the expanded flue gas flow at the turbine outlet 132 are predicted instead of being measured. The gas turbine system further comprises a predicted emissions monitoring system 180 that receives information regarding the gas mixture at the gas mixture outlet 154 of the mixing unit 150. In particular, the predicted emissions monitoring system 180 can be configured to receive at least the mixing ratio (e.g., of fuel and inert gas) or the content of the gas mixture (e.g., of fuel, inert gas, and additional fuel) at the gas mixture outlet 154 of the mixing unit 150. Advantageously, information regarding the gas mixture (in particular its content) is provided to the predicted emissions monitoring system 180 by the control unit 140, and the control unit 140 is connected to a fuel gas analyzer 160 fluidly coupled to the mixture outlet 154. In other words, the fuel gas analyzer 160 is configured to provide information regarding the gas mixture (in particular its actual content) at the gas mixture outlet 154 to the control unit 140. Advantageously, the predicted emissions monitoring system 180 may be configured to receive information regarding the temperature and / or pressure of the gas mixture at the gas mixture outlet 154, and the temperature and / or pressure may be measured by the fuel gas analyzer 160 and supplied to the control unit 140.

[0028] The predicted emissions monitoring system 180 is configured to predict at least one parameter of the expanded flue gas flow at the turbine outlet 32, in particular based on the information regarding the received gas mixture. Advantageously, the predicted emissions monitoring system 180 can predict the amount of NOx in the expanded flue gas flow and / or the amount of CO in the expanded flue gas flow and / or the amount of CO2 in the expanded flue gas flow.

[0029] The predicted emissions monitoring system 180 can provide parameters (plural possible) to a control unit 140 that controls the operation of the gas turbine system 2000 based on the predicted parameter(s), preferably based on at least the amount of NOx in the expanded flue gas stream and / or the amount of CO in the expanded flue gas stream and / or the amount of CO2 in the expanded flue gas stream. In particular, as already described, the control unit 140 can control the opening and closing of the regulating valve based on the parameter(s) predicted by the predicted emissions monitoring system 180.

[0030] Advantageously, the gas turbine system 2000 can further comprise devices for measuring other parameters, in particular sensors, as follows (these devices can also be integrated in whole or in part into the mixing unit and / or the compressor section and / or the combustor section and / or the turbine section). - Ambient pressure and temperature, and / or - Expanded flue gas temperature, and / or - Ambient relative humidity, and / or - Pressure drop between the compressor inlet 11 and the ambient pressure, and / or - Pressure drop between the turbine outlet 32 and the ambient pressure, and / or - Pressure and temperature of the oxidant (e.g., air) at the compressor outlet 12, and / or - Flame temperature, and / or - Flame stability and kinetics, and / or - Fuel composition and characteristics (pressure, temperature, Lower Heating Value = LHV, Modified Wobbe Index = MWI, combustion ratio...).

[0031] Advantageously, one or more of these other parameters can be supplied to the control unit 140, which can take them into account and control the operation of the gas turbine system 2000, and in particular can perform a trade-off between the amount of undesirable emissions (e.g., NOx and / or CO and / or CO2) and the gas turbine performance. Advantageously, the control unit 140 can also take into account, for example, based on predictions and gas turbine performance maps, the aging phenomenon of the gas turbine system and / or the mechanical degradation / wear of the high-temperature gas components (i.e., the gas turbine components exposed to the high-temperature flow) and control the operation of the gas turbine system 2000.

[0032] Note that according to some embodiments, one or more emissions can be measured as shown in FIG. 1 and one or more emissions can be predicted as shown in FIG. 2.

[0033] The embodiment of the gas turbine system 3000 in FIG. 3 is similar to the embodiment in FIG. 1, except that at least the predicted emissions monitoring system is configured to make predictions based on artificial intelligence (AI), and in particular includes an artificial neural network configured to contribute to the predictions.

[0034] Embodiment 280 of the predicted emissions monitoring system is configured to be electrically coupled to a continuous emissions monitoring system 270 fluidly coupled to the turbine outlet 232 and has an input configured to measure turbine emissions, particularly NOx emissions and / or CO2 emissions and / or CO emissions. Typically, the continuous emissions monitoring system 270 consists of sensor arrangements, particularly NOx meters and / or CO2 meters and / or CO meters. The system 270 and the connection lines are drawn as dashed lines because the continuous emissions monitoring system may not be a permanent component of the gas turbine system and may only be present during the installation phase (e.g., during the first, for example, 2 to 20 hours of operation) and / or during the initial operation phase (e.g., during the first, for example, 200 to 2000 hours of operation) and / or during system operation checks. The AI-based predicted emissions monitoring system 280 can be configured to be set up (e.g., calibrated) at the factory and / or during installation and can be configured to be trained during installation and / or during initial operation, and the training is based on the emissions actually measured at the outlet of the gas turbine system.

[0035] According to some variations of the embodiment of FIG. 3, the continuous emissions monitoring system 270 may be permanently present and may be used, for example, not only for training the AI-based predicted emissions monitoring system 280 but also for other purposes.

[0036] The gas turbine systems 1000, 2000, 3000 shown in FIGS. 1 to 3 can implement a method of reducing the content of undesirable emissions, such as harmful emissions, particularly NOx and / or CO and / or CO2, in the flue gas discharged from the turbine outlets 32, 132, 232, by adjusting the mixing ratio of the gas mixture of fuel gas and inert gas (and thus the content of the gas mixture of fuel gas, inert gas, and additional fuel gas) supplied to the combustor sections 20, 120, 220. As already described, the content of NOx and / or CO and / or CO2 in the flue gas may be measured by the continuous emission monitoring systems 70, 270 and / or predicted by the predicted emission amount monitoring systems 180, 280, and the measured and / or predicted content is provided to the control units 40, 140, 240 so that the mixing ratio or content of the gas mixture is adjusted (substantially in real time) by the control units 40, 140, 240. However, the control units 40, 140, 240 can control the operation of the gas turbine systems by optimizing other parameters as well, preferably by performing a trade-off between the content of NOx and / or CO and / or CO2 in the flue gas (the maximum value of which is regulated and varies by country) and the performance of the gas turbine systems, such as power output and / or efficiency.

[0037] According to a first possibility, when the gas turbine system operating conditions are high ambient air temperature and high relative humidity (e.g., T = 40°C, RH = 0.85), the content of NOx and / or CO and / or CO2 in the flue gas is less than the content of NOx and / or CO and / or CO2 in the flue gas under ISO conditions (T = 15°C, RH = 0.6). Thus, the nitrogen content in the gas mixture can be reduced, and the power output of the gas turbine system can be advantageously reduced. According to another possibility, when the content of CO and / or CO2 in the flue gas increases, the power output can be kept substantially constant by increasing the hydrogen and nitrogen content in the gas mixture. According to another possibility, the volume content ratio of the inert gas can be increased up to the design limit of the diffusion flame combustion performed by the combustor section of the system.

[0038] It should be noted that the gas turbine systems 1000, 2000, and 3000 disclosed herein may also be provided with other solutions and / or devices for reducing or removing pollutants in the exhaust gas, such as steam injection into the combustion chamber.

Claims

1. A gas turbine system (1000, 2000, 3000), comprising: - A compressor section (10) having a compressor inlet (11) and a compressor outlet (12), configured to receive an uncompressed oxidant stream at the compressor inlet (11), compress the oxidant, and provide a compressed oxidant stream at the compressor outlet (12); - A combustor section (20) having a combustor inlet (21), a combustor outlet (22), and a fuel supply conduit (23), wherein the combustor inlet (21) is fluidly coupled to the compressor outlet (12), the combustor section (20) includes a combustion chamber fluidly coupled to the combustor inlet (21), the combustor outlet (22), and the fuel supply conduit (23), configured to perform diffusion flame combustion of fuel and oxidant in the combustion chamber, and configured to provide a flue gas stream at the combustor outlet (22); - A turbine section (30) having a turbine inlet (31) and a turbine outlet (32), wherein the turbine inlet (31) is fluidly coupled to the combustor outlet (22), the turbine section (30) is configured to expand the flue gas stream and discharge an expanded flue gas stream at the turbine outlet (32); - A control unit (40) configured to control the operation of the gas turbine system (1000); characterized in that the gas turbine system (1000) further comprises a mixing unit (50) having a fuel gas inlet (51), an inert gas inlet (52), and a gas mixture outlet (54), the gas mixture outlet (54) being fluidly coupled to the fuel supply conduit (23) of the combustor section (20); the gas turbine system (1000) further comprises a fuel gas analyzer (60) configured to determine the content of the gas mixture at the gas mixture outlet (54) and provide the content to the control unit (40); the mixing unit (50) is configured to mix fuel gas and inert gas and provide a gas mixture at the gas mixture outlet (54) under the control of the control unit (40), the gas mixture having a mixing ratio depending on the content of the flue gas. A gas turbine system (1000, 2000, 3000).

2. The gas turbine system (1000, 2000, 3000) according to claim 1, wherein the fuel gas is hydrogen or a gas mixture mainly containing hydrogen.

3. The inert gas contains nitrogen and / or carbon dioxide and / or argon and / or helium and / or H ２ O and / or a mixture thereof, and preferably, the inert gas is nitrogen or a gas mixture mainly containing nitrogen. The gas turbine system (1000, 2000, 3000) according to claim 1.

4. The mixing unit (50, 150, 250) further comprises an additional fuel gas inlet (53, 153, 253), and the mixing unit (50, 150, 250) is configured to mix the fuel gas, the additional fuel gas and the inert gas and provide the gas mixture at the gas mixture outlet (54, 154, 254). The gas turbine system (1000, 2000, 3000) according to claim 1.

5. The additional fuel gas includes natural gas and / or ammonia and / or liquefied petroleum gas (LPG) and / or biofuel and / or electric fuel and / or syngas and / or CO. The gas turbine system (1000, 2000, 3000) according to claim 4.

6. Further comprising a continuous emission monitoring system (70, 270) fluidly coupled to the turbine outlet (32, 232) and configured to measure at least one parameter of the expanded flue gas flow and provide the at least one parameter to the control unit (40, 240). The at least one parameter is the amount of NOx in the expanded flue gas flow. The gas turbine system (1000, 3000) according to claim 1.

7. The continuous emission monitoring system (70, 270) is further configured to measure at least another parameter of the expanded flue gas flow and provide the at least another parameter to the control unit (40, 240). The at least another parameter is the amount of CO and / or CO2 in the expanded flue gas flow. The gas turbine system (1000, 3000) according to claim 6.

8. Further comprising a predicted emission monitoring system (180, 280) configured to receive at least the mixing ratio or content of the gas mixture at the gas mixture outlet (154, 254) from the control unit (140, 240), predict at least one parameter of the expanded flue gas flow, and provide the at least one parameter to the control unit (140, 240). The at least one parameter is the amount of NOx in the expanded flue gas flow. The gas turbine system (2000, 3000) according to claim 1.

9. The predicted emissions monitoring system (180, 280) is further configured to predict at least one other parameter of the expanded flue gas stream and provide the at least one other parameter to the control unit (140, 240), wherein the at least one other parameter is the amount of CO and / or CO2 in the expanded flue gas stream, the gas turbine system (2000, 3000) according to claim 8.

10. The control unit (40, 140, 240) controls the operation of the gas turbine system (1000, 2000, 3000) based on the at least one parameter that is measured or predicted, the gas turbine system (1000, 2000, 3000) according to claim 6 or 7 or 8 or 9.

11. The control unit (40, 140, 240) controls the operation of the gas turbine system (1000, 2000, 3000) based on the at least one other parameter that is measured or predicted, the gas turbine system (1000, 2000, 3000) according to claim 7 or 9.

12. The mixing unit (50, 150, 250) comprises a fuel gas regulating valve and an inert gas regulating valve, and the control unit (40, 150, 250) is configured to regulate the opening and closing of the fuel gas regulating valve and the inert gas regulating valve, the gas turbine system (1000, 2000, 3000) according to claim 1.

13. The mixing unit (150, 250) further comprises an adjustment valve for the additional fuel gas, and the control unit (140, 240) is configured to regulate the opening and closing of the adjustment valve for the additional fuel gas, the gas turbine system (2000, 3000) according to claim 4.

14. The predicted emissions monitoring system (280) is configured to make predictions based on artificial intelligence, in particular, comprises an artificial neural network configured to contribute to the prediction, the gas turbine system (3000) according to claim 8 or 9.

15. - A continuous emissions monitoring system (270) fluidly coupled to the turbine outlet (232) and electrically coupled to the predicted emissions monitoring system (280), configured to measure turbine emissions, or - An input configured to be electrically coupled to a continuous discharge monitoring system (270), wherein the continuous discharge monitoring system (270) is fluidly coupled to the turbine outlet (232) and configured to measure the turbine discharge rate, and further comprising: The predicted discharge rate monitoring system (280) is configured to be set up during factory and / or installation, and configured to be trained during installation and / or initial operation, the training being based on the measured discharge rate, the gas turbine system (3000) according to claim 14.

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